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DOE OSTI2017

Impact of the EISA 2007 Energy Efficiency Standard on General Service Lamps

The Energy Policy and Conservation Act of 1975, as amended by the Energy Independence and Security Act of 2007 (EISA 2007), requires that, effective beginning January 1, 2020, the Secretary of Energy shall prohibit the sale of any general service lamp (GSL) that does not meet a minimum efficacy standard of 45 lumens per watt. This is referred to as the EISA 2007 backstop. The U.S. Department of Energy recently revised the definition of the term GSL to include certain lamps that were either previously excluded or not explicitly mentioned in the EISA 2007 definition. For this subset of GSLs, we assess the impacts of the EISA 2007 backstop on national energy consumption, carbon dioxide emissions, and consumer expenditures. To estimate these impacts, we projected the energy use, purchase price, and operating cost of representative lamps purchased during a 30-year analysis period, 2020-2049, for cases in which the EISA 2007 backstop does and does not take effect; the impacts of the backstop are then given by the difference between the two cases. In developing the projection model, we also performed the most comprehensive assessment to date of usage patterns and lifetime distributions for the analyzed lamp types in the United States. There is substantial uncertainty in the estimated impacts, which arises from uncertainty in the speed and extent of the market conversion to solid state lighting technology that would occur in the absence of the EISA 2007 backstop. In our central estimate we find that the EISA 2007 backstop results in significant energy savings of 27 quads and consumer net present value of $120 billion (at a seven percent discount rate) for lamps shipped between 2020 and 2049, and carbon dioxide emissions reduction of 540 million metric tons by 2030 for those GSLs not explicitly included in the EISA 2007 definition of a GSL.

29 ENERGY PLANNING, POLICY, AND ECONOMY↗

DOE OSTI2018

Methodology to Calculate the ACE and HPQ Metrics Used in the Wave Energy Prize

The U.S. Department of Energy's Wave Energy Prize Competition encouraged the development of innovative deep-water wave energy conversion technologies that at least doubled device performance above the 2014 state of the art. Because levelized cost of energy (LCOE) metrics are challenging to apply equitably to new technologies where significant uncertainty exists in design and operation, the prize technical team developed a reduced metric as proxy for LCOE, which provides an equitable comparison of low technology readiness level wave energy converter (WEC) concepts. The metric is called 'ACE' which is short for the ratio of the average climate capture width to the characteristic capital expenditure. The methodology and application of the ACE metric used to evaluate the performance of the technologies that competed in the Wave Energy Prize are explained in this report.

17 WIND ENERGY↗

DOE OSTI2018

Economical and Environmentally Benign Extraction of Rare Earth Elements (REES) from Coal & Coal Byproducts

This final report provides a complete summary of the activities, results, analytical discussion, and overall evaluation of the project titled “Economical and Environmentally Benign Extraction of Rare Earth Elements (REES) from Coal & Coal Byproducts” under DOE Award Number DE-FE-0027155 that started in March 2016 and ended December 2017. Fly ash was selected as the coal-byproduct source material due to fact that it is readily available with no need for extensive methods to obtain the material, it is produced in large quantities (>50 million tons per year) and had REE concentrations similar to other coal-byproducts. The selected fly ash used throughout this project was from the Mill Creek power generating facility operated by Louisville Gas and Electric located in Louisville, KY and was subjected to a variety of physical and chemical characterization tests. Results from fusion extractions showed that the selected fly-ash had a TREE+Y concentration of 480 ppm with critical REEs concentration of 200 ppm. The fly ash had an outlook ratio of 1.25 and an estimated value of $16-$18 worth of salable REEs per 1-tonne of fly ash. Additional characterizations by optical evaluation, QEMSCAN, XRD, size fractionation, and SEM analysis showed the fly ash consisted of small glassy spherules with a size range between 1 to 110 µm (ave. diam. of 13 um), was heterogeneous in chemical composition (main crystalline phases: aluminum oxides and iron oxides) and was primarily an amorphous material (75 to 80%). A simple stepped approach was completed to estimate the total REE resource quantity. The approach included REE characterization of the representative samples, evaluation of fly-ash availability, and final determination estimated resource availability with regards to REE grade on a regional and national scale. This data represents the best available information and is based upon the assumptions that the power generating facility where the fly-ash was obtained will use the same coal sources (actual mines were identified), the coal materials will have relatively consistent REE concentrations, and the REE extraction process developed during this project can achieve 42% REE recovery (validated and confirmed). Calculations indicated that the estimated REE resource is approximately 175,000 tonnes with a current estimated value of $3,330MM. The proposed REE extraction and production process developed during this project used four fundamental steps; 1) fly-ash pretreatment to enhance REE extraction, 2) REE extraction by acid digestion, 3) REE separation/concentration by carbon adsorption and column chromatography, and 4) REE oxide production. Secondary processing steps to manage process residuals and additional processing techniques to produce value-added products were incorporated into the process during the project. These secondary steps were not only necessary to manage residuals, but also provided additional revenue streams that offset operational and capital expenditures. The process produces one value product stream (production of zeolite Na-P1), a solids waste stream, and one liquid stream that met RCRA discharge requirements. Based upon final design criteria and operational parameters, the proposed system could produce approximately 200 grams of REOs from 1-tonne of fly-ash, thereby representing a TREE+Y recovery of 42% (project target of > 25%). A detailed economic model was developed to evaluate both CAPEX and OPEX estimates for systems with varying capacities between 100 kg to 200 tonnes of fly ash processed per day. Using a standard system capacity of 10 tonne/day system, capital costs were estimated at $88/kg fly ash while operating costs were estimated at approximately $450/kg fly ash. This operating cost estimate includes a revenue of $495/tonne of fly ash processed from the value-added product produced from the system (zeolite Na-P1). Although operating cost savings due to zeolite production were significant, the capital + operating cost for a 10 tonne system was more expensive than the total dollar value of REEs present in the fly ash material. Specifically, the estimated cost per 1-tonne of fly ash treated is approximately $540 while the estimated value of REEs in the fly ash is $18-$20/tonne. This is an excessive difference showing that the proposed process is not economically feasible strictly on the basis of REE revenue compared to extraction costs. Although the current proposed system does not produce sufficient quantities of REEs or additional revenue sources to offset operational and capital costs, supplementary factors including US strategic concerns, commercial demands, and defense department requirements must be factored. At this time, the process developed during this project provides foundational information for future development of simple processes that require low capital investment and one that will extract a valuable quality and quantity of REE oxides from industrial waste.

01 COAL, LIGNITE, AND PEAT↗

DOE OSTI2018

Prospective Costs, Benefits, and Impacts of U.S. Renewable Portfolio Standards

These slides were presented at a webinar on January 9, 2017. The slides overview a report that evaluates the future costs, benefits, and other impacts of renewable energy used to meet current state renewable portfolio standards (RPSs). It also examines a future scenario where RPSs are expanded. The analysis examines changes in electric system costs and retail electricity prices, which include all fixed and operating costs, including capital costs for all renewable, non-renewable, and supporting (e.g., transmission and storage) electric sector infrastructure; fossil fuel, uranium, and biomass fuel costs; and plant operations and maintenance expenditures. The analysis evaluates three specific benefits: air pollution, greenhouse gas emissions, and water use. It also analyzes two other impacts, renewable energy workforce and economic development, and natural gas price suppression. The analysis finds that the benefits or renewable energy used to meet RPS polices exceed the costs, even when considering the highest cost and lowest benefit outcomes.

29 ENERGY PLANNING, POLICY, AND ECONOMY↗

DOE OSTI2018

Development of Mixed-Salt Technology for CO 2 Capture from Coal Power Plants

SRI International (SRI), in collaboration with Stanford University, OLI Systems (OLI), Politecnico de Milano (PoliMi), and Aqueous Systems Aps (ASApS) performed a 45-month effort to develop a promising Mixed-Salt Process (MSP) for carbon dioxide capture. The MSP combines existing ammonia and potassium-carbonate technologies with improved absorption steps for rate enhancement and ammonia emission reduction and a novel selective regeneration process with a high-pressure CO 2 product to introduce a new and advanced transformational solvent-based technology. The striking advantages of the SRI MSP include: low heat of reaction, high loading of CO 2 , high-pressure regeneration of > 99% pure dry CO 2 , low sensitivity to impurities, low process cost, use of a non-degradable low-cost solvent with a very low carbon footprint for its production, low emissions, and reduced water use compared to the state-of-the-art ammonia-based and amine technologies. The overall objective of the project was to develop and test a solvent-based CO 2 capture technology that can capture CO 2 from existing or new pulverized coal (PC) power plants at low cost. Our specific goal was to test SRI’s newly developed MSP at the large bench-scale level to demonstrate that the process could capture CO 2 at high efficiency (> 90%) with very high CO 2 loading (> 10 wt.%), require less than 2 GJ/tonne for solvent regeneration, and produce a CO 2 stream at high pressure with a purity > 95 vol.%. This 45-month MSP development program was designed to conduct (1) extensive test campaigns with different process flowsheet variants, and (2) detailed thermodynamic, kinetic, and process modeling. These tests and models were very important to identify any issues associated with the process in the early stages and then resolve them before moving into the next scale-up (> 1 MWe scale) testing. The technology development plan consisted of balanced experimental and process modeling activities as shown in Figure i. Such an approach reduces the risks associated with the process operability at large scales and provides capital and operating expenditure (CAPEX/OPEX) predictions with improved accuracies. Under the MSP development program at SRI, we performed an aggressive testing campaign with individual subsystems as well as integrated CO 2 capture and regeneration system to identify the best operating conditions. The project was carried out in two budget periods (BP1 & BP2).

20 FOSSIL-FUELED POWER PLANTS↗

DOE OSTI2018

Analysis of Supply Chains and Advanced Manufacturing of Small Hydropower Systems

Clean energy manufacturing is a sector of increasing importance both in the United States and worldwide. In the United States, it has been presented as an engine for job creation in a sector of the U.S. economy that was hit hard by the 2008-2009 recession. The Clean Energy Manufacturing Analysis Center (CEMAC), sponsored by the U.S. Department of Energy (DOE), conducts credible, objective, industry-relevant, recurring, and consistent analyses of clean energy technologies. In this project, the National Renewable Energy Laboratory (NREL) and the Oak Ridge National Laboratory (ORNL) collaborated in a hydropower manufacturing and supply chain analysis primarily for U.S. small hydropower (SHP) market to provide insights on supply chain constraints, manufacturing cost, location factors, and opportunities for hydropower using advanced manufacturing technologies. The goal of the project is to improve understanding of the manufacturing opportunities in the U.S. hydropower supply chain, specific competitive advantages, and factors for manufacturing location decisions for SHP. These insights could be used to inform investment and research strategies, policy, and other decisions that could promote economic growth and strengthen U.S. manufacturing capabilities. The project scope included a design for manufacturing and assembly (DFMA) costs analysis and a levelized cost of electricity (LCOE) sensitivity analysis of modular, representative SHP turbines. A representative SHP system was chosen to be made up of two 5 megawatt (MW) turbines, as these Kaplan style turbines could be useable for many non-powered dams (NPDs) across the U.S. The sensitivity analysis used the Integrated Design and Assessment (IDEA) tool, which has helped highlight the impact of the turbine equipment cost on the potential capital expenditure (CAPEX) and LCOE of the installed, representative system. In addition, the project team analyzed international tradeflows (e.g., export and import of hydropower turbines and the parts used in hydropower systems). As part of this project, hydropower stakeholder interviews were undertaken to help identify insights related to hydropower manufacturing opportunities for U.S. players in SHP, the country-specific manufacturing advantages in the United States and threats, and key factors behind manufacturing location decisions made by the SHP industry. Key opportunities for the US SHP market and industry include: Foreign export markets such as Chile, China, Columbia, India and Japan, have an estimated 71,795 MW of technical potential that could be serviced with SHP installations. Utilization of existing manufacturing capacity and expertise, along with economies of scale benefits, could result in increased global competitiveness through lower investment requirements and component costs, which could lead to increased U.S. strength in the export of SHP systems and components. Technology advances such as modular turbine designs, standardized units for conduit systems, precast systems, and improved powertrain technologies could help reduce costs, particularly for manufacturing a small number of units. The DOE is also exploring modular hydropower designs, which would integrate standard independently-produced components, validated to meet multiple specifications. Using modules in product design simplifies manufacturing activities such as inspection, testing, assembly, and purchasing, may increase economies of scale to lower total system cost. There are significant opportunities for the use of composites and Additive Manufacturing (AM) for hydropower components, when design changes are made to hydropower systems. By taking advantage of the corrosion resistance, light-weighting and structural benefits, composites and AM could help significantly alter hydropower structures and installations.

13 HYDRO ENERGY↗

DOE OSTI2018

Residential Electricity Prices: A Review of Data Sources and Estimation Methods

This paper presents an empirical study of residential electricity prices based on a compilation of tariff data collected for Lawrence Berkeley Lab's Tariff Analysis Project (TAP). We also review other data sources commonly used to estimate residential sector electricity prices, including utility data published by the Energy Information Administration (EIA), the Typical Bills reports published by the Edison Electric Institute, and household-level electricity consumption and expenditure data included with the EIA's Residential Energy Consumption Surveys. We define three different types of price that can be estimated from the data, construct estimation methods, compare the results and evaluate the relative strengths and weaknesses of each approach. We examine several sources of variation including seasonal, regional, industry structure, and the magnitude of baseline household consumption. The tariff data are also used to explore the impact of moving households from standard tariffs to time-of-use pricing, and to summarize how this affects predictions of electricity bill savings for both demand reduction and demand shifting. (auth)

29 ENERGY PLANNING, POLICY, AND ECONOMY↗

DOE OSTI2018

Development of Mixed-Salt Technology for CO 2 Capture from Coal Power Plants (Final Report)

SRI International (SRI), in collaboration with Stanford University, OLI Systems (OLI), Politecnico de Milano (PoliMi), and Aqueous Systems Aps (ASApS) performed a 45-month effort to develop a promising Mixed-Salt Process (MSP) for carbon dioxide capture. The MSP combines existing ammonia and potassium-carbonate technologies with improved absorption steps for rate enhancement and ammonia emission reduction and a novel selective regeneration process with a high-pressure CO 2 product to introduce a new and advanced transformational solvent-based technology. The striking advantages of the SRI MSP include: low heat of reaction, high loading of CO 2 , high-pressure regeneration of > 99% pure dry CO 2 , low sensitivity to impurities, low process cost, use of a non-degradable low-cost solvent with a very low carbon footprint for its production, low emissions, and reduced water use compared to the state-of-the-art ammonia-based and amine technologies. The overall objective of the project was to develop and test a solvent-based CO 2 capture technology that can capture CO 2 from existing or new pulverized coal (PC) power plants at low cost. Our specific goal was to test SRI’s newly developed MSP at the large bench-scale level to demonstrate that the process could capture CO 2 at high efficiency (> 90%) with very high CO 2 loading (> 10 wt.%), require less than 2 GJ/tonne for solvent regeneration, and produce a CO2 stream at high pressure with a purity > 95 vol.%. This 45-month MSP development program was designed to conduct (1) extensive test campaigns with different process flowsheet variants, and (2) detailed thermodynamic, kinetic, and process modeling. These tests and models were very important to identify any issues associated with the process in the early stages and then resolve them before moving into the next scale-up (> 1 MWe scale) testing. Such an approach reduces the risks associated with the process operability at large scales and provides capital and operating expenditure (CAPEX/OPEX) predictions with improved accuracies. Under the MSP development program at SRI, we performed an aggressive testing campaign with individual subsystems as well as integrated CO 2 capture and regeneration system to identify the best operating conditions. The project was carried out in two budget periods (BP1 & BP2).

20 FOSSIL-FUELED POWER PLANTS↗

DOE OSTI2018

Boil-off losses along LH2 pathway

Losses along the LH 2 pathway are intrinsic to the utilization of a cryogenic fluid. They occur when the molecule is transferred between 2 vessels (liquefaction plant to trailer, trailer to station storage, station storage to pump or compressor, then fuel cell electric vehicles …) and when the fluid is warmed up due to heat transfer with the environment. Those losses can be estimated with good accuracy using thermodynamic models based on conservation of mass and energy, providing the thermodynamic states are correctly described. Indeed, the fluid undergoes various changes as it moves along the entire pathway (2 phase transition, super-heated warming, non-uniform temperature distributions across the saturation film) and accurate equations of state and 2 phase behavior implementations are essential. The balances of mass and energy during the various dynamics processes then enable to quantify the boil-off losses. In this work, a MATLAB code previously developed by NASA to simulate rocket loading is used as the basis for the LH 2 transfer model. This code implements complex physical phenomena such as the competition between condensation and evaporation and the convection vs. conduction heat transfer as a function of the relative temperatures on both sides of the saturated film. The original code was modified to consider real gas equations of state, and some semi-empirical relationships, such as between the heat of vaporization and the critical temperature, were also replaced by a REFPROP equivalent expression, assumed to be more accurate. Non-constant liquid temperature equations were added to simulate sub-cooled conditions. It is shown that although trailer depressurization and transfer losses from the receiving vessel during a LH 2 delivery may constitute the largest sources of losses, those can be greatly reduced and even eliminated if CFR/DOT regulations are properly applied and if no-vent fill methods are implemented, particularly for a stationary LH2 storage operating at reasonably low pressure (45 psia or so). As such, it is expected that the only remaining boil-off losses for a refueling station would come from the LH 2 pump (utilization and idling), pump vessel cool down/warm up, and environment heat transfer. Based on experimental data measured at LLNL on the Linde 875 bar LH 2 cryo-pump and results from the model, and extrapolating for refueling stations of various sizes, it can be shown that boil-off losses can vary from 15% of delivered LH 2 for a 100 kg/day, 5% at 400 kg/day, and down to less than 2% for stations above 1,800 kg/day (for a system similar to the one at LLNL). Less boil-off is to be expected for LH 2 pumps dispensing at 350 bar, so that less than 0.7% can be expected above 1,800 kg/day station capacities. At last, boil-off recovery solutions are briefly analyzed, including compressors, cryo-coolers and stationary fuel cell. Their economic value is strongly related to the costs of H2 and of the electricity needed to perform the recovery, on top of the initial capital expenditures. Effective boil-off could be reduced to 0.6-1% for a 2,000 kg/day station if adequate recovery solutions are used.

08 HYDROGEN↗

DOE OSTI2018

Risk and Cost Analysis of Utilizing FLEX Equipment for O&M Cost Reduction in Nuclear Power Plants

Several Nuclear Power Plant (NPP) operators in USA have announced to close their plants despite there are remaining years on their operating licenses. The cause of these closures is because the plant operators suffer financial losses. Approximately 80% of USA NPPs would have undergone financial losses if they were situated in a deregulated electricity market. In a deregulated market, electricity generators are independent entities separate from the transmission companies and Independent System Operator (ISO) which manages the market. NPPs in this market are termed merchant NPPs, and their profitability is determined solely from electricity generation revenues. Meanwhile, regulated and public power nuclear units’ profitability is determined by the regulatory process in place for each unit. Due to the complexity of differentiating each regulated and public power NPP’s regulations 36 NPPs are at an immediate risk of retiring early to stop losses, while 27 units will likely to follow in the long run. Today, cost is well-recognized and important factor in NPP decision-making that cannot be ignored. Therefore, it is essential to consider risk and cost together in decision-making to strengthen the position of the nuclear industry in an economically challenging energy market. With operational and maintenance (O&M) cost at 70% of the total operating expenditure of an NPP and some plants closing prematurely despite excellent safety record, there is an urgent need to address the high O&M cost. One of the novel entities that provide additional safety resulting in reduced risk of nuclear power plants is Flex equipment. Flex strategies were postulated by the US NRC in the wake of Fukushima Dai-chi accident to address beyond design-basis accidents and improve plant flexibility. Flex strategy comprise both onsite and off-site component storage for the provision of additional materials and equipment. This work explored innovative ways of utilizing the onsite Flex equipment during regular plant operation, for purposes in addition to the intended use of beyond design basis accidents. This report describes the risk and cost analysis of using Flex equipment during regular or unplanned maintenance.

46 INSTRUMENTATION RELATED TO NUCLEAR SCIENCE AND ↗

DOE OSTI2018

Energy Production Through Anaerobic Digestion in the Food-Waste-Energy Nexus

The addition of a second anaerobic digestion process at Landis Sewerage Authority (LSA) in Vineland, N.J., was a project designed to accomplish several major objectives. First, it would replace an inactive digester that Landis had been “cannibalizing” for parts to keep its primary digester operating. Second, and more importantly to the New Jersey Department of Agriculture, this project provided an opportunity to create a tangible, working apparatus to demonstrate whether food waste and manure (provided by food processors and farmers) could be used efficiently and effectively to create gas used to power a co-generation unit that supplies electrical power to run the Authority’s sewage-treatment operations. Additionally, the project would further test an additive (BAE) for its effects on overall gas production. NJDA specifically sought to avoid using the grant funds for a feasibility study that did not result in a working demonstration project, and that goal was met by producing an actual second digestion process at Landis. Finally, this project provided the opportunity to demonstrate how the re-use and re-purposing of existing infrastructure could help lower the costs of providing an energy-production unit without having to build it from the ground up. A key to achieving those goals was limiting the use of outside contractors to build the digestion process. Instead, LSA employed the engineering services of its executive director and another employee to design the project, and the talents of its in-house employees to construct and install components of the digestion process. This minimized expenditures for outside providers while also enabling LSA to have greater control over both the design and construction. Those controls on costs enabled a full fact-finding mission to similar operations in Ohio and Indiana in August 2015. The visits allowed comparisons that found the Midwest operations (at least at two of the three locations) were less constrained by odor control issues than Landis is under New Jersey environmental regulations, and that the Fair Oaks Dairy Farm in Indiana had successfully incorporated its digester operation into its wide-ranging and popular “farm experience” attraction that includes restaurants, stores selling products from the farm’s output, tours of massive robotic milking parlors and a visitors’ center featuring “4D movies” about dairy farming and the use of manure in creating energy. The visit to Fair Oaks allowed the NJDA/Landis team to also examine whether a Fair Oaks “farm experience” model could be replicated in the Mid-Atlantic region, with its higher density of population, given the need for additional odor-control components to account for the closer proximity to population centers, but also benefiting from a larger potential close-in visitor base. Again, by streamlining the fact-finding process and using ground transportation instead of airfare, the travel line-item of the project budget was essentially halved. That enabled the creation of a video about the Landis project, which can be sent electronically – “e-travel,” so to speak – to other states and agencies that want to learn more about what was created in Vineland.

09 BIOMASS FUELS↗

DOE OSTI2018

Advanced Vehicle Testing and Evaluation Final Technical Report Encompassing Project Activities From October 1, 2011 to April 30, 2018

The Advanced Vehicle Testing and Evaluation (AVTE) project incorporated the conduct of advanced technology vehicle and infrastructure testing in the U.S. Department of Energy (DOE) Advanced Vehicle Testing Activity (AVTA). It was the only activity tasked by DOE to conduct independent field evaluations of vehicle technologies that use advanced technology systems and subsystems in vehicles that reduce petroleum consumption. The results are available through reports published on the AVTA website at http://avt.inl.gov/. The AVTE project provided insight into advanced vehicle technology's long-term performance, durability, maintenance, and lifecycle costs that cannot be found elsewhere. The site is a resource for DOE stakeholders and the public to gain knowledge on advanced technology vehicle progress and innovation. Vehicles tested included light and heavy-duty vehicles with conventional, hybrid, plug-in hybrid, and all-electric propulsion systems. Vehicles were tested on closed tracks and chassis dynamometers, as well as operated on public roads, in fleet operations, and over prescribed routes. All testing was controlled by procedures developed specifically to support such testing. Testing and evaluations were conducted in the following phases: Development and refinement of test procedures, which established testing procedures; Baseline performance testing, which established a performance baseline; Accelerated reliability testing, which determined vehicle reliability; Fleet testing, used to evaluate vehicle economics in fleet operation, and End of test performance evaluation. Test results from all aspects of testing were posted by Idaho National Laboratory (INL) to their website. This final report documents work conducted for the entirety of contract DE-EE0005501 by Intertek Testing Services NA, Inc. (Intertek). The contract was performed from October 1, 2011 through April 30, 2018, and includes 18 amendments to the original award with the most recent Amendment 18 dated March 28, 2018. The final budget for the AVTE project totaled 20,220,873 dollars. As a cooperative agreement, Intertek was obligated to provide cost share of 4,044,175 dollars, leaving 16,176,698 dollars as the Federal share of the agreement. Actual total expenditure for the AVTE project was 20,286,850 dollars. The full 16,176,698 dollars Federal share was expended and 4,110,152 dollars of cost share was provided by Intertek. This resulted in an over-share of 65,977 dollars. There were 106 light-duty on-road vehicles vehicles tested in both fleet and accelerated reliability testing. One additional vehicle was rented to obtain performance testing only. Three heavy-duty truck and trailer combinations were tested as part of the semi-autonomous driving with heavy-duty vehicles in a platoon. Overall project scope and direction was determined between Intertek, DOE, and technical teams from Idaho National Laboratory (INL), Argonne National Laboratory (ANL), and National Renewable Energy Laboratory (NREL). The project was administered by the DOE’s National Energy Technology Laboratory (NETL).

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗

DOE OSTI2018

Field Demonstration of The Krauklis Seismic Wave In A Novel Mva Method For Geologic CO 2 Storage

The Energy & Environmental Research Center (EERC) conducted a feasibility study of a new, low-impact geophysics monitoring method designed to incrementally track the saturation front of CO 2 injected into a reservoir. The method leverages a new way of transmitting energy from the surface to the reservoir and employs a new subsurface signal called the Krauklis wave (K-wave) and other guided waves for seismic monitoring. The EERC partnered with Seismos, Inc., the company that holds the exclusive technology license for this method, to advance development of K-wave technology, and Denbury Onshore, LLC, to field-test the system. The system was field-tested at Denbury’s Bell Creek oil field, currently undergoing CO 2 -based enhanced oil recovery (EOR) in southeastern Montana. The K-wave system uses a wellhead-mounted source to propagate energy down the wellbore in the form of a tube wave and through the well perforations into the reservoir. Part of the energy transmitted through the perforations into the reservoir converts to slow moving K-waves and/or other guided waves that are expected to propagate through the formation to neighboring wells. The propagated signal would induce tube waves in the neighboring wells that return to the surface to be recorded with a wellhead-mounted receiver. The propagation time of the signal is directly affected by the presence of CO 2 between the wells, so the difference in transit time of the returning signal between pre- and postinjection data sets could be used to help define the lateral extent of a CO 2 saturation front. Objectives of the study were to demonstrate, validate, and evaluate the K-wave method’s ability to monitor the morphology of injected CO 2 and estimate saturation distribution. Results from the demonstration were to be compared to conventional 4-D surface seismic methods, dynamic reservoir simulations, and CO 2 breakthrough data to validate the technology and provide useful information that may result in improvements. Prior to mobilizing for the full-scale K-wave baseline survey, a field test was conducted to better understand wellhead hardware configurations and test the response from the Bell Creek reservoir using three wells. Useful operational information resulted but signal from the first-generation gas release/gas injection source was not recorded in neighboring wells. After the initial field test, numerical modeling of the K-wave method was initiated using parameters specific to the Bell Creek Field. Modeling results indicated that the fundamental concepts behind the K-wave method exhibited problems and revealed a significantly greater attenuation of the signal at the wellbore perforations than expected, totaling on the order of 10-8 from source well to receiver well over a 400-m well spacing. Modeling also showed that greater source frequency bandwidth was needed to produce guided waves within a 30-foot-thick reservoir layer such as that at Bell Creek and that reservoir layer seismic velocity would need to be slower than the velocities of the bounding layers in order to act as a wave guide opposite to what exists at Bell Creek. Modeling results prompted a second field test with a stronger, second-generation displacement source developed in the interim. Concurrent with the second field test, a 3-D seismic survey was acquired to serve as a baseline for project validation and to serve as a monitor data set for the portion of the project area where CO 2 injection had already commenced. The new source was tested using a four-well geometry and failed to produce a detectable signal, which appeared to confirm modeling results and indicated that the Bell Creek Field is not an ideal site for the K-wave test. It was concluded that a source with sufficient strength and bandwidth could not be built to overcome the factors discovered by the modeling within a reasonable amount of time. Several other sites undergoing CO 2 -based EOR were also evaluated; however, none of these sites was amenable because of geology, limitations of source and receiver hardware, or the advanced state of the CO 2 flood. In addition, two other configurations of the source and receiver layout were considered; however, these design modifications either changed the scope of the project or did not meet the goals of the Carbon Storage Program. In consultation with the U.S. Department of Energy (DOE) Project Manager and Technology Manager, a no-go decision was invoked to forego additional expenditures as the technology would not meet current project objectives. Project activities to date have moved the technology forward by developing modeling equations that can be applied elsewhere, advanced the state of wellhead sensors and sources, and spurred improvements to field operations. The 3-D seismic survey in the project area and the dynamic reservoir simulations done as part of this study have provided value for ongoing and future synergistic activities at Bell Creek related to DOE carbon storage goals.

54 ENVIRONMENTAL SCIENCES↗

DOE OSTI2012

A Decade of Economic Change: Fuel Prices and Households

This working presentation focuses on the changes in fuel prices and household income during the period of 2000 to 2010. In real terms, household money incomes have fallen, while fuel prices have increased. Comparisons are made between increased driving cost and changes in income, by quintile. Other areas examined include the timing of energy price increases and recessions and a breakout of prices and consumption to determine the driving factor behind energy expenditure increases.

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗

DOE OSTI2019

Sector-Specific Methodologies for Subnational Energy Modeling

The National Renewable Energy Laboratory (NREL) and the Department of Energy's Office Strategic Priorities and Impact Analysis Office sought to address gaps in subnational energy data availability. This report describes the methodologies and analysis developed to estimate electricity and natural gas consumption and expenditures for the residential, commercial, and industrial sectors within each U.S. city.

29 ENERGY PLANNING, POLICY, AND ECONOMY↗

DOE OSTI2019

California Time-of-Use (TOU) Transition: Effects on Distributed Wind and Solar Economic Potential

Time-of-use (TOU) retail energy rates price electricity differently by the time of day, thereby communicating to consumers the costs of supplying electricity throughout the day. This study evaluates the impact of Decision D.15.07-001, which mandates a transition to default TOU rates in California, on the economic viability of behind-the-meter distributed wind and solar systems. We assess viability through 'economic potential,' a metric we define as the amount of generation capacity that exceeds a specified rate of return (5.4%) and therefore would be economic to construct; we do not attempt to project deployment or adoption. In addition, we identify cost improvements needed for a robust distributed wind market and the specific counties and sectors with substantial economic potential. Over the scenarios considered, model results indicate realistic pathways to reaching a robust, 1-GW distributed wind market in California though solar economic potential was found to be substantially larger than that of wind. Distributed wind's capacity factor does not appear to be strongly correlated to the periods of peak electricity prices as set by utility's TOU periods. Because of this disassociation and nuances in the billing of tiered electricity, the transition to TOU is projected to moderately decrease distributed wind economic potential and increase that of distributed solar. However, a limitation of this analysis is that it does not factor in the change in rate values as California works toward its goal of 100% renewables. As variable renewable energy penetration increases to meet this goal, our results suggest that wind generation will become increasingly correlated to periods of peak electricity prices. Increased variable renewable penetration, especially of solar, is likely to shift periods of higher electricity demand to later in the evening, and any periodic adjustments in TOU periods to reflect these new periods of demand will positively affect the value of wind generation more than the value of solar generation. High distributed wind capital costs are a significant barrier to large scale adoption; we explore the sensitivity of capital cost reductions on distributed wind economic potential. We find that distributed wind economic potential increases substantially in 2020 for capital costs below 3 dollars/W - particularly for residential- and commercial-scale turbines; capital costs must fall below 2 dollars/W in 2030 to support a significant increase in economic potential, in large part due to the expected continued cost reductions in solar. We identified an upper limit to the state's behind-the-meter distributed wind economic potential at approximately 5 GW. Overall, California exhibits over 1 GW of economic potential for distributed wind by 2030, even with the moderate decrease in potential under TOU. This potential is represented mostly by Southern California, which sees the most notable increase in economic viability as capital expenditure prices decline.

17 WIND ENERGY↗

DOE OSTI2019

Catalytic Upgrading of Thermochemical Intermediates to Hydrocarbons (Final Report)

A lot of activity in catalytic pyrolysis and hydroprocessing occurred in the past 10-15 years with notable successes and failures; however, very little technical information is available in the open literature from pilot-scale studies such as those performed in this project. Besides, the next step along the technology commercialization pathway is to scale-up the catalytic biomass pyrolysis process, integrate this technology with a hydroprocessing unit, and demonstrate the long-term operation and performance of the integrated process; notably, these were achieved in this project. RTI International has developed a single-step catalytic biomass pyrolysis process to produce a hydrocarbon-rich bio-crude intermediate. This bio-crude is more thermally stable and has lower oxygen content than conventional biomass fast pyrolysis oil, so it can be effectively and efficiently upgraded with traditional hydroprocessing technology to produce gasoline and diesel. Our partner, Haldor Topsøe, has developed a strategy for hydroprocessing bio-crude intermediates based on extensive catalyst and process development in support of converting vegetable oils and waste greases into high-quality diesel fuel. The goal of the originally proposed project was to demonstrate an advanced biofuels technology that integrates a catalytic biomass pyrolysis step and a hydroprocessing step to produce infrastructure-compatible biofuels. The specific technical goals of this project were 1) to optimize the catalytic biomass pyrolysis process to achieve high degree of deoxygenation, while maximizing the bio-crude production, 2) improve bio-crude thermal stability, 3) evaluate the impact of bio-crude quality in the hydroprocessing step, 4) minimize hydrogen demand of the integrated process, and 5) maximize biofuels yields. This project showed that it is technically feasible to use non-zeolitic solid acid catalyst to consistently generate bio-crude with 20% oxygen content and that these liquids can be effectively hydrotreated into low oxygen fuel blendstocks. The reproducibility of the small-scale pyrolysis yields at the 1 tonne/day scale is an achievement worth noting and the effect of pyrolysis temperature on biocrude yields and quality was investigated at the pilot scale. Additionally, advanced analytical techniques were used to analyze bio-crude to investigate the effect of process conditions and feedstock on the concentration and speciation of oxygen-containing compounds. Insights into the impact of oxygen content and oxygen speciation on bio-crdue upgrading were also sought. Clearly, more successful upgrading correlated with bio-crudes with lower oxygen content. This was most evident when partially upgraded bio-crude with 55-90% less oxygen compared to the starting bio-crude was blended with straight run diesel and hydrotreated without any noticeable increase in pressure drop across the reactor or any measurable loss of hydrodenitrification (HDN) activity. Minimizing hydrogen demand while maximizing biofuels yield are the desired outcomes for the integrated process. In summary, several technical challenges remain before catalytic biomass pyrolysis becomes a commercial reality, most notably bio-crude yields and quality still need to be improved. The integrated catalytic biomass pyrolysis hydroprocessing scheme being developed produces intermediates that can be refined for use as drop-in hydrocarbon replacement fuels. From a technology perspective, this advanced biofuel technology produces liquid transportation fuels that can leverage capital expenditures in the existing petroleum refining and distribution infrastructure. From a business perspective, this technology does not face potential market limitations as other nonhydrocarbon biofuels caused by oxygenated blending limitations and fuel certification for light-duty vehicle applications.

09 BIOMASS FUELS↗

DOE OSTI2019

Benchmarking Wind Power Operating Costs in the United States: Results from a Survey of Wind Industry Experts

This paper draws on a survey of wind industry professionals to clarify trends in the operational expenditures (OpEx) of U.S. land-based wind power plants. The paper also highlights key drivers of those trends. We find that average all-in lifetime OpEx has declined from approximately $\$$80/kW-yr ($\$$35/MWh) for projects built in the late 1990s to a level that is approaching $\$$40/kW-yr ($\$$11/MWh) for projects under construction in 2018. Turbine operations and maintenance (O&M) costs—inclusive of scheduled and unscheduled maintenance—represent the single largest component of overall OpEx and the primary source of cost reductions over the last decade. We observe wide ranges of OpEx over time; for example, survey respondents cite a range in average expected costs for projects commissioned between 2015 and 2018 from $\$$33/kW-yr to $\$$59/kW-yr. Notably, these broad ranges include high levels of variability in both turbine O&M costs and non-turbine OpEx. Potential technical and strategic drivers of this variability are highlighted. We also use historical OpEx learning rates, showing a 9% OpEx reduction for each doubling of global installed wind capacity, to project a further $\$$5–$\$$8/kW-yr (12%–18%) OpEx reduction from 2018 to 2040. When compared with the broader literature, these findings suggest that continued OpEx reductions may contribute 10% or more of the expected reductions in land-based wind’s levelized cost of energy. Moreover, these estimates may understate the importance of OpEx owing to the multiplicative effects through which operational advancements influence not only O&M costs but also component reliability, performance, and plant-level availability—thereby affecting levelized costs though OpEx reduction and by enhancing annual energy production and plant lifetimes. Given the limited quantity and comparability of previously available OpEx data, the data and trends reported here may usefully inform OpEx assumptions used by electric system planners, analysts, modelers, and research and development managers. The results may also provide useful benchmarks to the wind industry, helping developers and asset owners compare their OpEx expectations with historical experience and other industry projections.

17 WIND ENERGY↗